Hydraulic fracturing is used to create subterranean fractures that extend from the borehole into the rock in order to increase the rate at which fluids can be produced from the formation. Generally, a fracturing fluid is pumped into the well at high pressure. Once natural reservoir pressures are exceeded, the fracturing fluid initiates a fracture in the formation which continues to grow during pumping. The treatment design generally requires the fluid to reach maximum viscosity as it enters the fracture.
The fracturing fluid typically contains a proppant which is placed within the produced fracture. The proppant remains in the produced fracture to prevent the complete closure of the fracture and to form a conductive channel extending from the wellbore into the treated formation.
Most fracturing fluids contain a viscosifying agent in order to increase the capability of proppant transport into the fracture. Suitable viscosifying agents include synthetic polymers, like polyvinyl alcohols, polyacrylates, polypyrrolidones and polyacrylamides, and polysaccharides, like guar gum (galactomannans) and guar gum derivatives. Exemplary guar or guar gum derivatives include hydroxypropyl guar (HPG), carboxymethyl guar (CMG) and carboxymethylhydroxypropyl guar (CMHPG) as well as high molecular weight non-derivatized guar.
Once the high viscosity fracturing fluid has carried the proppant into the formation, breakers are used to reduce the fluid's viscosity. In addition to facilitating settling of the proppant in the fracture, the breaker also facilitates fluid flowback to the well. Breakers work by reducing the molecular weight of the viscosifying agent. The fracture then becomes a high permeability conduit for fluids and gas to be produced back to the well.
Common breakers for use in fracturing fluids include chemical oxidizers, such as hydrogen peroxide and persulfates. Chemical oxidizers produce a radical which then degrades the viscosifying agent. This reaction is limited by the fact that oxidizers work in a stiochiometric fashion such that the oxidizer is consumed when one molecule of oxidizer breaks one chemical bond of the viscosifying agent. Further, at low temperatures, such as below 120° F., chemical oxidizers are generally too slow to be effective and other catalysts are needed to speed the rate of reaction. At higher temperatures, chemical oxidizers function very rapidly and often must be encapsulated in order to slow the rate of reaction. Alternatives have been sought for maximizing the efficiency of chemical oxidizers in the well treatment fluid at in-situ conditions.
In addition to chemical oxidizers, enzymes are also commonly used as breakers. Enzymes are catalytic and substrate specific and catalyze the hydrolysis of specific bonds on the polymeric viscosifying agent. An enzyme will degrade many polymer bonds in the course of its lifetime. Unfortunately, enzymes operate under a narrow temperature range and their functional states are often inactivated at high temperatures.
More recent interest in hydraulic fracturing has focused on slickwater fracturing which is often used in the stimulation of tight gas reservoirs. In slickwater fracturing, a well is stimulated by pumping water at high rates into the wellbore, thereby creating a fracture in the productive formation. Slickwater fluids are basically fresh water or brine having sufficient friction reducing agent(s) to minimize tubular friction pressures. Generally, such fluids have viscosities only slightly higher than unadulterated fresh water or brine. Such fluids are much cheaper than conventional fracturing fluids which contain a viscosifying agent. In addition, the characteristic low viscosity of such fluids facilitates reduced fracture height growth in the reservoir during stimulation.
When aqueous fluids (like slickwater fracturing fluids) not containing a viscosifying polymer are used in stimulation, the pressure during the pumping stage is normally lower than that required in fracturing treatments using viscosifying polymers. The frictional drag of the frac fluid is lowered by the presence of the friction reduction agent(s) in the slickwater fluid. While slickwater fluids introduce less damage into the formation in light of the absence of viscosifying polymers, the friction reduction agent, if left in the formation, can cause formation damage. Effective means of degrading friction reduction agents in slickwater fracturing fluids is desired in order to minimize damage to the treated formation.
Similar to stimulation fluids, other fluids used to treat wells must be removed following the completion of the treatment operation for which such fluids are used. For instance, polymeric viscosifying agents frequently used in drilling muds and well completion fluids have a damaging effect since they tend to interfere with other phases of drilling and/or completion operations, as well as production of the well after such operations are finished. For example, drilling fluids tend to seep into the surrounding formation forming a filter cake on the wall of the wellbore. The filter cake sometimes can prevent casing cement from properly bonding to the wall of the wellbore. It is important in such operations that the viscosifying agents and other components of the drilling mud be removed from the well in order to enhance the recovery of hydrocarbons. Conventionally, oxidative breakers have been used to degrade the polysaccharide-containing filter cakes and residual damaging materials which reduce their viscosity.
In addition to seeking alternative breakers for use in high temperature environments, there has been an increasing demand for the development of well treatment agents, including breakers, which are environmentally friendly.